Well-designed virtual power plant programs integrate multiple energy technologies and vendors, streamline customer experiences during program enrollment and participation, operate for five years or longer and incentivize distributed energy resource adoption to drive further customer participation, RMI said in a flipbook released on June 12.
The flipbook draws on 15 case studies from states and utilities across the United States, including California’s comprehensive Emergency Load Response and Demand Side Grid Response programs, Rocky Mountain Power’s solar- and battery-focused Wattsmart Battery program, Arizona Public Service’s Cool Rewards smart thermostat program and EV charging management programs operated by Duke Energy, DTE Energy and Xcel Energy.
The case-study VPPs collectively provide 1.5 GW of capacity from 3.9 million enrolled customers, according to the flipbook.
The case studies show that utilities “don’t have to start from scratch” when designing and deploying VPPs, said Mary Tobin, an associate in RMI’s Carbon-Free Electricity practice and the flipbook’s lead author. Utility program managers can instead “look to their peers across the country [and] apply takeaways from the case studies that are most applicable,” she added.
Most of the VPP programs were developed to address specific utility needs, such as reliability, resiliency or decarbonization, showing that “there isn’t a one-size-fits-all VPP,” Tobin said. Some programs dispatch resources daily, she noted; Hawaiian Electric's Battery Bonus program reduces daily peak load on Oahu by 22 MW, the equivalent of 1% of the system’s installed firm capacity, according to the flipbook.
The flipbook also included three recommendations for “reimagined utility practices”: incorporate VPPs into generation and distribution planning, proactively engage policymakers and regulators around effective VPP policies like performance payments and “transform business practices” to enable more effective VPP design and operation.
While most of the case studies looked at programs serving residential customers, a handful incorporated commercial and industrial customers, including those managed by Portland General Electric, Puget Sound Energy and National Grid.
Those programs were effective in thinking about demand response more broadly by working with commercial customers to identify which connected loads could be reduced when signaled, Tobin said. This process involved more customer education but ultimately resulted in more flexible participation designs that worked for the enrollees, she added.
The flipbook was written with “utilities’ needs in mind” but offers value for utility regulators, grid operators and other electricity system stakeholders, Tobin said.
The impetus for the flipbook was RMI’s observation that utilities are increasingly interested in VPPs as tools to manage projected load growth, thermal generator retirements and higher summer peaks exacerbated by climate change, Tobin said.
Because the prospect of setting up a VPP can be daunting for utilities that haven’t done it before, RMI wanted to include detailed guidance showing how utilities design VPPs, engage customers in them and use them to provide grid services alongside actionable case studies demonstrating how those actions look in practice across a variety of U.S. markets, she added.
“We hope this becomes a foundational resource to show how VPPs are addressing grid needs,” she said.
Correction: In a previous version of this story, a battery program in Hawaii was misidentified. It is Hawaiian Electric's Battery Bonus program on Oahu.
